Earthing System Design for UK Solar PV Systems

Earthing System Design for UK Solar PV Systems: Why Getting It Wrong Costs More Than the Grid Connection

According to the Energy Networks Association, over 40% of G99 application delays in utility-scale solar PV projects in the UK trace back to incomplete or non-compliant protection and earthing submissions. Earthing system design for UK solar PV systems is not a box-ticking exercise at the tail end of an EPC project. It is a foundational engineering decision that determines how protective devices coordinate, how fault currents are managed, and whether a DNO will approve your G99 application the first time around. For EPC contractors working across large-scale solar developments, understanding TN-S, TT, and IT network configurations is the difference between a smooth energisation and a costly re-design cycle.

What BS 7671 and IEC 60364 Actually Say About Earthing Systems for Solar PV

The framework governing BS 7671 earthing solar installations in the UK is drawn from two intersecting standards. BS 7671 (the IET Wiring Regulations, 18th Edition) provides the domestic and commercial installation baseline, while IEC 60364 solar earthing requirements extend this into the engineering detail required for large-scale generation assets. Together, they define three primary earthing system types, each identified by a two or three letter code describing how the source and exposed conductive parts of an installation relate to earth.

The first letter identifies the relationship of the power system to earth. T means one point is directly connected to earth. I means all live parts are isolated from earth or connected through a high impedance. The second letter identifies the relationship of the exposed conductive parts of the installation to earth. T means exposed conductive parts are connected directly to earth, independently of any earthing of the source. N means exposed conductive parts are connected to the earthed point of the power system at source.

In the context of utility-scale solar PV, these definitions carry significant consequences for fault current magnitude, protective device selection, and the level of monitoring infrastructure required on site.

TN-S Earthing Configuration for Solar PV

In a TN-S solar earthing system, the neutral and protective earth conductors are kept entirely separate throughout the installation. The source neutral is directly earthed, and all exposed conductive parts are connected to a dedicated protective earth conductor that runs back to the source. For solar PV projects connecting at LV, DNOs in the UK traditionally provide a TN-S supply where the earth is provided via the cable sheath of the distribution network.

What makes TN-S particularly relevant in solar EPC work is the relatively low earth fault loop impedance it provides. Under the correct Zs conditions verified during commissioning, a TN-S installation can rely on overcurrent protective devices alone to disconnect a fault within the disconnection times prescribed by BS 7671 Table 41.1. This means that if your calculated and measured Zs values meet the threshold for the protective device in circuit, you do not necessarily need residual current devices for basic fault protection. For large inverter output circuits where RCD selectivity can be technically complex, this is a meaningful engineering advantage.

However, in practice, most utility-scale solar projects introduce multiple earth electrodes across a large site footprint. This changes the character of the earth fault loop and demands careful coordination of earthing conductor sizing back through to the main earthing terminal. The solar PV earth fault protection philosophy on a TN-S system must account for step and touch potential gradients across the array field, particularly where cable trenching runs through varying soil resistivity zones.

TT Network Solar PV: Higher Zs, Different Protection Requirements

The TT network solar PV configuration is common across rural UK sites where the DNO does not provide an earth terminal. In a TT system, the source neutral is earthed at the supply transformer, but the installation earth is provided by a separate, independent electrode at the installation premises. These two earths are electrically separate.

The consequence of this independence is a significantly higher earth fault loop impedance compared to TN-S. When a line-to-earth fault occurs on a TT system, the fault current must flow through the installation earth electrode, through the general mass of earth, and back through the supply transformer earth. This impedance is typically high enough that overcurrent devices will not operate within required disconnection times. This is precisely why BS 7671 mandates the use of RCD protection on TT systems for final circuits up to 32A, and why EPC engineers designing larger circuits must verify compliance through calculated maximum Zs values for the specific RCD operating current selected.

For a real-world perspective on what this means during commissioning: on a 5 MWp ground-mounted solar project in rural Somerset, the measured earth electrode resistance at the LV switchboard was 18 ohms. The TT system loop impedance under fault conditions meant a 100A MCCB protecting the inverter output board could not guarantee disconnection within 0.4 seconds. The resolution required the installation of a 300mA time-delayed RCD at the main distribution board, with selectivity carefully verified against downstream 30mA RCDs protecting measurement and communications equipment in the inverter rooms. That commissioning exercise added three working days and required re-submission of the protection coordination schedule to the DNO before energisation could proceed.

IT Earthing Systems in Battery Storage and EV-Integrated Solar Projects

The IT earthing configuration, where all live parts are isolated from earth or connected through a sufficiently high impedance, is making a clear appearance in the latest generation of solar PV projects that integrate battery energy storage systems (BESS) and EV charging infrastructure. Understanding why requires a look at the operational logic of IT systems rather than just the standard definitions.

In an IT system, the first earth fault does not cause a supply interruption. Because the system is isolated from earth at source, a single line-to-earth fault results in a low fault current limited by the system capacitance and any intentional impedance to earth. The installation can continue operating while the fault is located and cleared. For a BESS facility that must meet strict grid stability obligations under its Power Purchase Agreement, or for an EV charging hub where downtime directly translates to revenue loss, this characteristic is commercially attractive.

However, the regulatory and engineering requirements that come with IT earthing are substantial. Per IEC 60364 solar earthing provisions and the specific requirements of IEC 61557-8, every IT system must be equipped with an Insulation Monitoring Device (IMD). The IMD continuously measures the insulation resistance between live conductors and earth, and must trigger an audible and visual alarm when insulation resistance falls to a pre-set threshold before a second fault occurs. A second fault on an IT system creates a line-to-line fault through earth, which produces fault currents comparable to a short circuit and can be dangerous if not immediately interrupted.

The IMD selection for solar-integrated BESS projects is more nuanced than standard industrial IT applications. PV arrays inherently have significant capacitance to earth due to module frame bonding and long DC cable runs across a field. This capacitive leakage current can cause nuisance tripping or false alarm conditions on IMDs designed for conventional AC industrial systems. EPC engineers must specify IMDs with AC and DC isolation monitoring capability, tuned to the expected capacitive leakage profile of the PV array. Manufacturers such as Bender and Dold publish correction factors and configuration guidance for these hybrid DC-AC IT environments that experienced designers must consult during the earthing system design phase.

How PVsyst Simulation Outputs Feed Into Earthing Conductor Sizing

One of the most frequently overlooked connections in solar EPC engineering is the relationship between PVsyst energy simulation outputs and the earthing conductor sizing process. Most EPC teams treat PVsyst as a yield modelling tool and treat the earthing design as a separate electrical engineering discipline. In practice, the two are directly linked through fault current data.

PVsyst generates short-circuit current data at string, combiner box, and inverter output level. While this data is primarily used for string fuse and cable sizing, it directly informs the maximum prospective fault current that earthing conductors must withstand and carry to allow protective devices to operate. Under BS EN 50522, which governs earthing of power installations exceeding 1 kV AC but is also referenced for MV design coordination, earthing conductor cross-sectional area must be calculated to withstand the thermal stress of the maximum fault current for the duration of protective device operation.

The formula prescribed is derived from the adiabatic equation: S equals I times the square root of t divided by k. Where S is the cross-section in square millimetres, I is the fault current in amperes, t is the disconnection time in seconds, and k is a material constant depending on conductor material, initial temperature, and insulation type. Feeding PVsyst-derived fault current values into this calculation, rather than using generic assumed values, produces a more defensible and correctly sized earthing conductor network. It also prevents the common mistake of under-sizing earthing conductors on high-yield sites with large parallel string arrangements, where aggregated fault currents at combiner boxes can be substantially higher than a designer accustomed to smaller systems might assume.

For EPC contractors wanting to understand how simulation data integrates with detailed electrical design from project inception, the guide on how a PV solar system is designed provides a useful framework for aligning these engineering workstreams from the outset.

DNO Earthing Requirements UK: What Changes at the MV Connection Point

When a solar PV project connects at medium voltage rather than LV, the DNO earthing requirements UK become substantially more complex. The earthing philosophy at the MV connection point is determined by the DNO’s network configuration and is communicated through the Protection and Control (P and C) schedule issued during the G99 application process. Understanding this schedule and aligning your earthing design to it is non-negotiable.

UK DNOs operate MV networks in one of two principal earthing configurations: solidly earthed neutral or resistance earthed neutral. The choice has profound implications for earth fault current magnitudes and the protection relay settings that will be required at the point of connection.

Solid Earthing vs. Resistance Earthing at MV Solar Substations

MV earthing solar substation design must begin with clarity on which earthing philosophy the DNO operates on its network at the point of connection. A solidly earthed neutral on the DNO network means that during an earth fault, the fault current is limited only by the impedances of the transformer windings and the cables in the fault path. This produces large earth fault currents, typically comparable to three-phase short-circuit levels, and demands robust protection at the site substation capable of detecting and clearing the fault rapidly.

In contrast, resistance earthing connects the transformer neutral to earth through a purposely inserted resistance. This limits earth fault current to a controlled and predictable level, typically between 100A and 1000A depending on the resistance value selected. Smaller fault currents reduce mechanical stress on switchgear, limit the extent of damage at the fault point, and reduce touch potential gradients across the substation earthing grid. However, they also require sensitive earth fault relays capable of detecting these lower fault currents reliably, and the DNO will specify minimum relay sensitivity settings that must be met.

For a 33 kV-connected 50 MWp solar project, the distinction between these two configurations directly affected the earthing grid design for the main substation. On a solidly earthed network, the calculated earth fault current at the 33/0.4 kV transformer neutral exceeded 12 kA for 0.5 seconds. BS EN 50522 sizing calculations for the earthing conductors within the substation compound required 240mm copper conductors for the main earthing ring, with verified step and touch potential values through a soil resistivity survey and computational modelling using software such as CDEGS or WinIGS. Had the designer assumed resistance earthing without checking the DNO’s P and C schedule, the earthing conductor sizing would have been dramatically inadequate for the actual fault current environment.

Transformer Neutral Earthing and G99 Application Alignment

The grid connection earthing requirements submitted during a G99 application must demonstrate that the site’s earthing design is consistent with the DNO’s protection philosophy. This includes specifying the transformer neutral earthing arrangement for the site step-up transformer, demonstrating that earth fault relay settings will detect the minimum fault current for the network earthing configuration, and confirming that the earthing grid has been designed to control touch and step voltages within the limits of BS EN 50522 Annex B.

DNOs will typically also require a soil resistivity test report, an earthing system design calculation report, and a proposed earthing layout drawing as part of the technical submission. Projects that enter the G99 process without this documentation prepared will face information requests that delay the application significantly. For a structured checklist of what to prepare before submitting, the solar design preparation checklist provides a practical starting point for EPC project managers and design leads.

Protective Device Coordination Across Earthing System Types

The interaction between earthing system type and protective device coordination is where many EPC designs encounter their most significant technical challenges. The earthing system determines the magnitude and character of fault currents. The protective device coordination study must demonstrate that every fault condition, from a high-impedance line-to-earth fault on a TT system to a bolted three-phase fault at an MV busbar, will be cleared by the correct device in the correct time, without causing unnecessary loss of supply to healthy parts of the installation.

For solar PV earth fault protection on TT systems, the verification process requires measured earth electrode resistance values, not assumed values. The following key steps define proper coordination on a TT system:

• Measure the installation earth electrode resistance using a dedicated earth tester with fall of potential or clamp-on method appropriate to the site conditions
• Calculate the maximum earth fault loop impedance including the DNO source impedance, supply cable impedance, and measured installation earth resistance
• Verify that the selected RCD operating current and maximum tripping time will achieve disconnection within BS 7671 requirements for the circuit voltage and system type
• Document the selectivity chain from final circuit RCDs through to the main RCD at the origin of installation
• Confirm that RCDs used on PV inverter output circuits are Type B rated to handle DC fault current components that may otherwise prevent operation of Type A or AC RCDs

For TN-S systems, the coordination approach relies on the following confirmed parameters:

• Prospective short-circuit current at each distribution board, confirmed from DNO network data and cable impedance calculations
• Maximum Zs for each protective device and circuit, verified by calculation and by measurement at commissioning
• Thermal withstand verification for earthing conductors under maximum prospective fault current conditions
• Confirmation that main bonding conductors are sized per BS 7671 Table 54.8 relative to the line conductor cross-section

Projects that want to accelerate the process of achieving grid connection approval with a compliant protection submission will benefit from reviewing the structured approach described in the guide to passing grid connection approval, which addresses the most common reasons EPC applications are returned by DNOs for additional information.

Practical Earthing Design Considerations for UK Solar EPC Contractors

Beyond the framework of standards and DNO requirements, experienced EPC contractors know that earthing design for solar PV involves a number of site-specific variables that generic design guides do not always address directly.

Soil resistivity across a large ground-mounted solar site rarely follows a uniform model. Agricultural land in the UK can exhibit seasonal variations in resistivity of two to one or greater between summer and winter conditions as soil moisture content changes. Earthing designs that use a single resistivity measurement taken during a dry summer period may produce earth electrode resistance values in winter that are significantly lower, potentially affecting the coordination of earth fault protection on systems where the earth fault loop impedance is critical to device operation.

For this reason, best practice on projects larger than approximately 5 MWp is to conduct seasonal soil resistivity surveys or to apply a conservative seasonal correction factor to the measured resistivity. The IEEE Std 80 and BS EN 50522 both provide guidance on soil resistivity modelling across layered earth conditions that experienced earthing design engineers apply through computational tools.

Corrosion of earth electrodes and earthing conductors in UK soil conditions is another long-term consideration that is frequently under-specified in EPC designs. Copper-bonded steel earth rods are widely used and appropriate for many UK soil conditions, but in areas with high chloride content such as coastal sites or sites near agricultural land with frequent fertiliser application, the corrosion rate can be significantly accelerated. Specifying solid copper earth rods or stainless steel rods in these environments, despite the higher material cost, protects the integrity of the earthing system over the 25 to 40 year operational life of the solar asset.

Frequently Asked Questions

What earthing system does a UK DNO typically require for a utility-scale solar PV connection?

For LV connections, UK DNOs typically provide a TN-S supply where the protective earth is delivered via the cable sheath. For MV connections at 11kV or 33kV, the DNO earthing philosophy is specified in the Protection and Control schedule issued during the G99 application process, and may require either solid neutral earthing or resistance earthing at the site step-up transformer depending on the DNO network configuration.

Why do TT systems require RCD protection on solar PV installations?

TT systems have independent earth electrodes at the source and installation, resulting in a high earth fault loop impedance. This impedance is typically too high for overcurrent devices to achieve disconnection within the time limits required by BS 7671. RCDs detect the residual fault current rather than relying on high fault current magnitudes, and are mandated to provide reliable earth fault disconnection on TT installations.

What is an Insulation Monitoring Device and when is it required on a solar PV project?

An Insulation Monitoring Device continuously measures the insulation resistance between live conductors and earth in an IT system. It is required on every IT earthing system under IEC 61557-8 to detect the first earth fault before a dangerous second fault can occur. On solar PV projects with integrated BESS or EV charging using IT earthing, the IMD must handle both AC and DC measurement in environments with high capacitive leakage from PV array cabling.

How does PVsyst data influence earthing conductor sizing?

PVsyst generates short-circuit current data at string, combiner, and inverter output level. These fault current values are used in the adiabatic equation specified by BS EN 50522 to calculate the minimum cross-sectional area of earthing conductors that can withstand the thermal stress of a fault before protective devices operate. Using PVsyst-derived values rather than assumed figures produces a more accurate and defensible earthing conductor sizing for the specific project.

What is the difference between solid neutral earthing and resistance earthing at an MV solar substation?

Solid neutral earthing connects the transformer neutral directly to earth, producing large earth fault currents limited only by system impedances. Resistance earthing inserts a purposely chosen resistor between the transformer neutral and earth, limiting earth fault current to a controlled level typically between 100A and 1000A. The DNO specifies which configuration applies to the network at the point of connection, and this determines the earthing grid design, protection relay sensitivity settings, and earthing conductor sizing requirements.

Why must Type B RCDs be used on PV inverter output circuits?

Solar PV inverters produce output waveforms that may contain DC fault current components or high-frequency residual currents. Type AC and Type A RCDs may not operate correctly when DC components are present. Type B RCDs detect and respond to smooth DC residual currents in addition to AC residual currents, making them the appropriate choice for circuits connected to PV inverter outputs.

How does soil resistivity affect solar PV earthing system design in the UK?

Soil resistivity directly determines the resistance of earth electrodes and the earthing grid. Higher resistivity produces higher electrode resistance, which on TT systems increases the earth fault loop impedance and may affect protective device coordination. UK agricultural soils exhibit seasonal resistivity variations of up to two to one between dry and wet conditions. Best practice for sites above approximately 5 MWp is to conduct seasonal surveys or apply conservative correction factors to ensure the earthing design remains compliant across all operating conditions.

Conclusion: Earthing System Design Is a First-Principles Decision, Not a Late-Stage Checklist

The earthing system type chosen for a UK solar PV project, whether TN-S, TT, or IT, determines a cascade of downstream engineering decisions that reach from protective device coordination through to G99 application submissions and long-term asset integrity. For EPC contractors operating in an environment where DNO application quality directly affects project timelines and development costs, treating earthing system design for UK solar PV systems as a front-end engineering priority rather than a commissioning afterthought is not just good practice. It is a commercial necessity.

The convergence of IEC 60364 solar earthing requirements, BS 7671 earthing solar regulations, and individual DNO protection philosophies means there is no single template that applies across all sites. Each project requires site-specific soil resistivity data, fault current analysis derived from actual simulation outputs, and a protection coordination study that directly references the DNO’s P and C schedule. The EPC teams that build this capability into their standard design workflow will consistently outperform those that treat earthing as a compliance formality.

Whether you are at the early feasibility stage reviewing DNO earthing requirements UK for a new development or preparing a detailed earthing design report to support a G99 submission, the principles covered in this article provide the technical foundation for making informed, defensible engineering decisions that stand up to DNO scrutiny and deliver safe, compliant solar assets for the long term.